1. Field of the Invention
The present invention relates generally to wellbore construction and more particularly to the construction of multiple wellbores which are interconnected downhole to form a manifold of pipelines in the reservoirs of interest. Provision is made for flow controls, sensors, data transmission, power generation, and other operations positioned in the lateral wellbores during the drilling, completion and production phases of such wellbores.
2. Background of the Related Art
To obtain hydrocarbons such as oil and gas, wellbores or boreholes are drilled from one or more surface locations into hydrocarbon-bearing subterranean geological strata or formations (also referred to herein as reservoirs). A large proportion of the current drilling activity involves drilling deviated and/or substantially horizontal wellbores extending through such reservoirs. To develop an oil and gas field, especially offshore, multiple wellbores are drilled from an offshore rig or platform stationed at a fixed location. A template is placed on the sea bed, defining the location and size of each of the multiple wellbores to be drilled. The various wellbores are then drilled from the template along their respective pre-determined wellpaths (or drilling course) to their respective reservoir targets. Frequently, ten to thirty offshore wells are drilled from an offshore rig stationed at a single location. In some regions such as the North Sea, as many as sixty separate wellbores have been drilled from an offshore platform stationed at a single location. The initial drilling direction of several thousand feet of each such wellbore is generally vertical and typically lies in a non-producing (non-hydrocarbon bearing) formation.
Each wellbore is then completed to produce hydrocarbons from its associated subsurface formations. Completion of a wellbore typically includes placing casings through the entire length of the wellbore, perforating production zones, and installing safety devices, flow control devices, zone isolation devices, and other devices within the wellbore. Additionally each wellbore has associated wellhead equipment, generally referred to as a "tree" and includes closure valves, connections to flowlines, connections for risers and blowout preventors, and other devices.
As an example, ten wellbores may be drilled from a single offshore platform, each wellbore having a nine-inch internal diameter. Assuming that there is no production zone for the initial five thousand feet for any of the wellbores, there would be a total of fifty thousand feet (five thousand for each of ten wellbores) of non-producing wellbore that must be drilled and completed, serving little useful purpose. It may, therefore, be desirable to drill as few upper portions as necessary from a single location or site, especially as the cost of the drilling and completing offshore wellbores can range from $100 to $300 per foot of wellbore drilled and completed.
Multilateral well schemes have been proposed since the 1920's. Various methods of constructing these well geometry's have been disclosed showing methods of creating the wellbores, methods of mechanically connecting casings in the various wellbores drilled, methods of sealing the casing junctions, and various methods of providing re-entry access to the lateral wellbores for remedial treatments.
Multilateral wellbore junction construction is currently thought of as fitting into one of six levels of complexity. Level 1 is generally thought of as open hole sidetracks where lateral wellbores are drilled from an open hole (uncased) section of the main well. No casing is present in the main well or lateral well at the junction of the two wellbores. This method is generally the least expensive but does not ensure wellbore stability, does not provide a method of easy lateral re-entry, and it does not seal the junction in a manner to allow future flow control of the lateral versus the main wellbore.
Level 2 multilateral junctions are those where the lateral exits from a cased main well using section miling or whipstock methods to create the exit. The lateral wellbore may be left as open hole or a liner may be run and "dropped off" outside the main well casing exit such that the lateral liner and main casing are not connected and an openhole junction results. This method is currently a little more costly than Level 1; it provides some more assurance of re-entry access to laterals, and it can provide some flow control of the various wellbores. It does not however protect or reinforce the junction area against potential collapse of the open hole wellbore wall.
Level 3 junctions provide laterals exiting from a cased main well and a lateral liner is run in the lateral wellbore and mechanically connected to the main casing but no seal of the junction is achieved. This method supports the borehole created and provides access to laterals but the lack of a seal at the junction can lead to sand production or fluid inflow or outflow into the junction rock strata. In many applications this inflow or outflow of fluids at junction depth is not desirable as the laterals may penetrate strata of different pressures and the unsealed junction could result in an underground blow out.
Level 4 junctions also provide a lateral wellbore exiting from a cased main well and a lateral liner is run into the lateral wellbore with the top end of the lateral casing extending back to the main casing with the junction of the lateral liner and main casing sealed with cement or some other hardening liquid material that can be pumped in place around the junction. This method achieves isolation of the junction from adjoining strata providing a sufficient length annular seal can be placed around the lateral liner and provided the main casing has an annular seal between the casing and the main wellbore wall. Various methods of reentry access to the laterals is provided using deflectors or other devices. The pressure seal integrity achieved in this type of wellbore junction is generally dependent on rock properties of the junction strata and cannot exceed the junction strata fracture pressure by more than a few hundred pounds per square inch. In addition the guaranteed placement and strength of liquid cementatious hardening materials in a downhole environment is extremely difficult with washouts causing slow fluid velocities, debris causing contamination of sealing materials, fluid mixing causing dilution, gelled drilling muds resisting displacement, etc. The junction may be isolated from adjoining zones but seal reliability specifically at the junction is difficult.
Level 5 systems generally provide lateral wellbores exiting from a cased main well. Liners are run in the lateral wellbore and may be "dropped off" outside the window in the main casing or a Level 4 type cemented intersection may be created. The Level 5 systems however use production tubulars and mechanical packer devices to mechanically connect and seal the main casing and lateral liners to each other. Level 5 systems can achieve a junction seal exceeding the junction strata capability by five to ten thousand psi. These systems do however restrict the diameter of access to the lateral and main casings below the junctions due to the relatively small tubular diameters compared to casing sizes. Well designs must also generally consider the possibility of a leak in the junction tubulars. This limits the application of Level 5 systems to generally those applications where the junction pressures are abnormal for the junction rock only due to surface applied pressures such as may be encountered in injection wells or during well stimulations. Flow rates achievable through such junctions are also restricted to the rates possible through the smaller diameter tubulars.
Level 6 junctions create a mechanically sealed junction between the main casing and lateral liner without using the restricting bores of production tubulars to achieve the seal. The methods devised to date generally are of two categories. One category uses prefabricated junctions in which one or both bores are deformed. This prefabricated piece is lowered into the well bore on a casing string and located in an enlarged or underreamed section of hole such that it can be expanded or unfolded into its original shape/size. The casing string with the prefabricated junction is then cemented in the wellbore. The lateral borehole is then drilled from the lateral stub outlet and a lateral liner is hung/sealed in the lateral stub outlet. A second category of Level 6 junction currently used creates an oversized main well borehole and full size underformed junctions are run into the main wellbore on the main casing. Laterals can then be drilled from a lateral stub outlet as described from the previous category.
FIGS. 1a to 1f illustrate several conventional methods 200a to 200f for forming multiple lateral wellbores into reservoirs 202a and 202b. Multiple lateral wellbores or drainholes 204 are conventionally drilled from the cased main wellbore 208 or from the openhole section 206 of the main wellbore. When constructing the laterals 204a from a cased hole 208, a whipstock 214 is usually anchored in main well casing 208 by means of a packer or anchoring mechanism 216. A milling tool (not shown) is deflected by the whipstock face 218 to cut a window 210 in the casing 208. The lateral wellbore 204a is then directionally drilled to intersect its targeted reservoir 202a. The whipstock face 218 is typically 1 to 6 degrees out of alignment with the longitudinal axis of the whipstock 214 and the lateral wellbore 204a is directed away from the main wellbore casing 208 at a substantially equal angle. The intersection or junction between the lateral liner 220 and the main well casing 208 thus created is elliptical in its side view, curved in its cross section, and lengthy due to the shallow angle of departure from the main well casing 208. This conventional prior art method 200a-d creates a geometry that is difficult to seal with appreciable mechanical strength or differential pressure resistance. Method 200e of FIG. 1e uses tubulars and packers to mechanically seal the junction but restricts the final production flow area and access diameters to the two production bores. Method 200f of FIG. 1f uses a prefabricated junction which is deployed in place in an underreamed or enlarged section of the wellbore. This method requires an enlarged wellbore to the surface or an underreamed portion. If the underreamed wellbore approach is used then current technology deforms the junction piece in the underrearned section and by nature of design uses a low yield strength material which causes low pressure ratings. Alternatively this method may use an oversized diameter main wellbore to allow a prefabricated junction to be placed at the desired depth.
In the conventional multilateral wellbore construction methods described above, the lateral borehole is typically drilled from the main casing and departs the main casing at a shallow angle of 1 to 6 degrees relative to the longitudinal axis of the main casing. Recently, however, multilateral wellbores have been constructed by drilling separate lateral wellbores towards the main well casing, from the outside of the main casing so that the downhole end of the lateral wellbore is located proximate perforations in the main wellbore or even intersecting with the main wellbore if possible. Production fluids such as hydrocarbons can, therefore, be flowed between the main wellbore and the lateral wellbores.
However, such prior methods of constructing multilateral wellbores do not provide a mechanical connection or other suitable seal against downhole pressures between the main wellbore and the lateral wellbores. Accordingly, in a particular application such conventional techniques may only be desirable in situations in which the lateral wellbore intersects a production zone co-extensive with a production zone of the main wellbore. The present invention provides a method of mechanically connecting the lateral liner to the main casing and sealing the junction, which may be beneficial for multilateral wellbore construction where it is desirable to intersect a main wellbore with lateral wellbores drilled from outside the main wellbore in a direction generally towards the main wellbore.
In operations in which high pressure connections are desired, the less desirable conventional drilling techniques described above may heretofore have been employed which require deviating the lateral wellbores from within the main, or parent, wellbore. However, these conventional multilateral wellbore construction techniques may also cause undue casing wear in the parent wellbore when many lateral wellbores are drilled from a common parent well. In such a case, the parent well casing may be exposed to thousands of drillpipe rotations and reciprocations executed in the drilling. This drilling process wears away the metal walls of the casing internal diameter. Drill pipe is also used over and over and is therefore commonly treated with a hard coating on the tool joints to minimize the wear on the drill pipe itself. This wear resistant coating on the drill pipe can increase the wear on the casing. Since the production of the wellbore typically flows through the parent wellbore to the surface, the parent casing typically must have sufficient strength after drilling wear to contain wellbore pressures while also accounting for corrosion and erosion expected during the production phase of the well. Accordingly, a need has arisen to provide mechanical connection methods and apparatus between lateral wellbores and parent wellbores for operations in which it may be beneficial to drill the lateral wellbores from outside the parent wellbore in a direction towards the parent wellbore.
Further, during the completion of a wellbore, a number of devices are utilized in the wellbore to perform specific functions or operations. Such devices may include packers, sliding sleeves, perforating guns, fluid flow control devices, and a number of sensors. To efficiently produce hydrocarbons from wellbores drilled from a single location or from multilateral wellbores, various remotely actuated devices can be installed to control fluid flow from various subterranean zones. Some operators are now permanently installing a variety of devices and sensors in the wellbores. Some of these devices, such as sleeves, can be remotely controlled to control the fluid flow from the producing zones into the wellbore. The sensors are used to periodically provide information about formation parameters, condition of the wellbore, fluid properties, etc. Until now the flow control devices and sensors have been installed in the main well production tubing necessitating a reduction in the production flow area for a given main casing size. For example devices are now available matching 51/2 inch nominal tubing to fit in 95/8 inch nominal casing. 7 inch nominal tubing could be used in 95/8 inch casing but the remotely operated production control devices are restricted to 51/2. The present invention provides a method of placing the production control devices out of the main casing and into the lateral wellbore so they do not restrict the main casing tubular design or size and yet production of each lateral wellbore is controlled independently.
In deepwater fields (generally oil and gas fields lying below ocean water depths greater than 1000 ft), the costs of field development are even more extreme than the costs previously mentioned. In these environments satellite wells might be used with seafloor flowlines connected back to a central seafloor manifold for processing and a flowline extends from the central manifold to the sea surface where it is connected to a floating vessel or from the central manifold along the seafloor to a nearby existing platform or pipeline infrastructure. In these deepwater applications the reservoir fluids are subjected to cold ocean floor temperatures (which are generally 40 degrees Fahrenheit or less). These cold temperatures can cause problems in flow assurance since many hydrocarbons contain waxes which will crystallize when the fluid is cooled and can plug pipelines or flowlines especially if flow is stopped for any reason. The typical solution is to insulate individual wellbore risers from the seafloor to the sea surface and/or to insulate flowlines on the seafloor or even make provisions for flowline heating. These solutions have an associated high cost. The present invention provides for connecting wellbores at reservoir depth such that the wellbore fluids remain at substantially reservoir temperatures and pressures until they reach a common outflow wellbore to the surface thus addressing a portion of the well flow assurance concerns.
Accordingly, there is a need for a method and apparatus for providing mechanical connections between a main wellbore and a lateral wellbore, in which the lateral wellbore has been drilled from outside the main wellbore in a direction generally towards the main wellbore. The present invention provides a method and apparatus for providing mechanical connections between a main wellbore and a lateral wellbore, in which the lateral wellbore has been drilled from outside the main wellbore in a direction generally towards the main wellbore
In addition, there is a need for measurement and control apparatus in the lateral wellbores so that production through the lateral wellbores can be controlled independent of the production through the main wellbore. The present invention provides measurement and control apparatus in the lateral wellbores so that production through the lateral wellbores can be controlled independent of the production through the main wellbore.